When oil and gas wells are no longer commercially viable, they must be abandoned in accord with government regulations. Abandonment requires that the installed tubulars, including all strings of tubing, pipe, casing or liners that comprise the multiple, nested tubulars of the well must be severed below the surface or the mud line and removed. Using explosive shape charges to sever multiple, nested tubulars in order to remove them has negative environmental impacts, and regulators worldwide are limiting the use of explosives. Therefore, a need exists for effective alternatives to the use of explosives for tubular severance in well abandonment.
Mechanical blade cutting and abrasive waterjet cutting have been implemented in response to new restrictive environmental regulations limiting the use of explosives.
Existing mechanical blade cutters utilized from the inside of the innermost casing, cutting out through each successive tubular of the multiple nested tubulars, requires multiple trips in and out of the wellbore. Such mechanical blade cutters require a rotary rig or some means of rotary drive in order to rotate the work string to which the mechanical blade cutter is attached. Rotary drive systems are both cumbersome and expensive to have at the work site. Existing mechanical blade cutters are deficient because, among other reasons, the mechanical blade cutters may break when they encounter non-concentric tubulars. Another deficiency is the limitation on the number of nested tubulars that may be severed by the mechanical blade cutter at one time or trip into the wellbore. An “inner” and “outer” string may be severable, if generally concentrically positioned in relation to each other. However, there is no current capability for severing a multiple non-concentrically (eccentrically) nested tubulars that provides consistent time and cost results in a single trip into the wellbore.
Most advances in the mechanical blade cutting art have focused on cut chip control and efficiency, rather than focusing on the fundamental issues of blade breakage and required, multiple, undesired trips of the apparatus in and out of a well. Thus these fundamental problems of existing mechanical blade cutting persist.
When cutting multiple, nested tubulars of significant diameters, for example 9 ⅝ inches outside diameter through 36 inches outside diameter, with at least two other nested tubulars of different sizes dispersed in between, the mechanical blade cutter must be brought back to the surface where successive larger cutting blades are exchanged for smaller cutting blades. Exchanging the smaller blades for larger blades allows the downhole cutting of successively larger diameter multiple, nested tubulars.
To access the downhole mechanical blade cutter, the user must pull the entire work string out of the wellbore and unscrew each work string joint until the mechanical blade cutter is removed from the bottom of the work string. After exchanging the mechanical blade cutter for a larger cutting blade, the work string joints are screwed back together, one after another, and tripped back into the wellbore. The mechanical blade cutter trip back into the wellbore to the previous tubular cut location for additional cutting is compromised because the length of the work string varies due to temperature changes or occasionally human error in marking or counting work string joints. Consequently, it is difficult to precisely align successive cuts with earlier cuts.
Many installed multiple, nested tubular strings in wells are non-concentric, meaning that the nested tubulars are positioned off center in relation to the innermost tubular. This is often the case because the outer tubulars do not have the same center diameter as the inner tubular. As a result of the multiple, nested tubulars being stacked or clustered to one side, i.e. non-concentric to each other, the density or amount of material being cut will vary circumferentially during cutting. Mechanical cutter blades sometimes experience breakage when cutting multiple, nested tubulars positioned non-concentrically in relation to each other. The blade cutter often breaks from the contact with the leading edge of a partial segment of the casing that remains after another segment of that casing has been cut away. The remaining portion of the casing forms a “C” or horseshoe-type shape when viewed from above. The blade cutter extends to its fullest open cut position after moving across a less dense material or open space (because that material has been cut away) and when the blade cutter impacts the leading edge of the “C” shaped tubular, the force may break off the blade. The breaking of a cutter blade requires again tripping out and then back into the well and starting over at a different location in the wellbore in order to attempt severing of the multiple, nested tubulars. Non-concentric, multiple, nested tubulars present serious difficulties for mechanical blade cutters. Severing non-concentric multiple, nested tubulars may take a period of days for mechanical blade cutters.
Existing abrasive waterjet cutters also experience difficulties and failures to make cuts through multiple, nested tubulars. Primarily, existing solutions relate to abrasive waterjet cutting utilizing rotational movement in a substantially horizontal plane to produce a circumferential cut in downhole tubulars. However, the prior art in abrasive waterjet cutters for casing severance often results in spiraling cuts with narrow kerfs in which the end point of the attempted circumferential cut fails to meet the beginning point of the cut after the cutting tool has made a full 360 degree turn. In other words, the cut does not maintain an accurate horizontal plane throughout the 360 degree turn, and complete severance fails to be achieved. Another problem encountered by existing abrasive waterjet cutting is the inability to cut all the way through the thicker, more widely spaced mass of non-concentrically positioned tubulars. In this situation, the cut fails to penetrate all the way through on a 360 degree circumferential turn. A further disadvantage of traditional abrasive waterjet cutting is that in order to successfully cut multiple, nested tubulars downhole, air must be pumped into the well bore to create an “air pocket” around the area where the cutting is to take place, such that the abrasive waterjet tool is not impeded by water or wellbore fluid. The presence of fluid in the cutting environment greatly limits the effectiveness of existing abrasive waterjet cutting.
Existing systems provide, verification of severance by welding “ears” on the outside of the top portion of the tubulars under the platform, attaching hydraulic lift cylinders, heavy lift beams, and then lifting the entire conductor (all tubulars) to verify complete detachment has been achieved. Basically, if the tubulars are able to be lifted from the well bore, it is assumed the severance was successful. When working offshore, this lifting verification process occurs before even more costly heavy lift boats are deployed to the site. This method of verification is both time-consuming and expensive.
There exist methods to mill windows via longitudinal, vertical travel in casing. However, these milling methods do not completely sever multiple, nested non-concentric tubulars for well abandonment. One such rotary milling method uses a whipstock, which must be deployed before the window milling process can begin. A rotary mill is then actuated against one side of a tubular along with a means of vertical travel, enabling a window to be cut through the tubular. However, this method does not permit 360 degree circumferential severance of multiple, nested tubulars and is not suited for the purpose of well abandonment.
This invention provides a safe and environmentally benign means of completely severing multiple, nested tubulars for well abandonment including overcoming the difficulties encountered by mechanical blade cutting, abrasive waterjet cutting or other means of tubular milling currently available.